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We are moving through interesting times for the global energy sector with transformations underway for the way people receive their energy. Renewables are making an indelible mark on the landscape and governments of all persuasions around the world are formulating policy shifts to suit their populist needs, which in turn is determining the look of the energy system of the future. Some of these governments are finding it hard to talk to each other, let alone develop energy markets, laying doubts into global energy security. Yet it seems not all is gloom and doom with forecasts by the International Energy Agency (IEA) suggesting global demand for natural gas will surge over the next 20 years, creating a phenomenal economic opportunity for Australia. Gas is forecast to remain the fastest-growing fossil fuel to 2040, with annual growth of 1.6 per cent. The IEA didn’t ignore the prospects for oil predicting. Oil and gas together will account for more than half of all global energy consumption in 2040 with oil to be the largest source of energy share (27 per cent) and gas the second largest (25 per cent).
By 2040, the IEA predicts gas production will have increased by 44 per cent to 5.4 trillion cubic metres, accounting for a quarter of global energy demand. This will result in a shift in trade flows towards the Asia-Pacific region, with China mooted as the country most likely to become the world’s largest gas-importing country, with net imports approaching the level of the European Union by 2040. This outlook is very positive news for Australia. Australia is in competition with Qatar for the title of the world’s largest LNG exporter over the first five months of 2019. We jumped ahead earlier this year as Qatar’s exports dipped, however that was short-lived with Qatar regaining the edge in May. Australia could be the world’s largest LNG exporter for the next few years, but this crown is expected to passed on once Qatar and The United States bring on new projects. Obviously, we will just have to keep punching away.
© Copyright Resources Roadhouse Pty Ltd September 2019
Cover Photo: Courtesy of Triangle Energy
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Whitebark Energy Limited (ASX: WBE)
Emerging oil producer, Whitebark Energy is on track to consolidate its position in the lucrative North American energy market on the back of further exploration success in Canada. During the September quarter Perth-based Whitebark Energy advanced its Wizard Lake project in the Canadian province of Alberta, successfully drilling its second well in an oil play with a current inventory of at least 20 well locations. Whitebark recently improved its land holding in the Wizard Lake oil field to a total gross area of around 3,705 acres. Early assessment of the gross potential of the field suggests that the ultimate size of the whole accumulation could be as large as 11.2 million barrels of oil equivalent (boe). The Rex-2 well followed on the success of Rex-1 and encountered an excellent quality reservoir to a depth of 3033 metres. Aside from intersecting a virtually continuous reservoir section over approximately 1500 metres from the casing shoe (at 1572m depth) to the bottom of the well, Rex-2 also revealed a number of excellent oil shows (fluorescence and cut), some elevated gas readings as well as a higher porosity (up to 21%) than the company’s Rex-1 well (15-18%). Rex-2 is currently complete following a 35 stage frac program ahead of initiating production. The drilling program to date has come in on schedule and on budget. Continued success in the initial part of the Wizard Lake project will help position Whitebark to internally fund the drilling program going forward. Whitebark initially acquired a 20 to 30 per cent working interest in the Canadian Joint Venture containing the Wizard Lake project after striking a deal with established TSX (Venture)-listed energy player Point Loma Resources back in 2014. It successfully spudded Rex-1 in late November last year, where initial flow testing recorded production rates of more than 300 barrels of oil per day (bopd) prior to completion of the test work.
Total oil from the 16 day flow test was 2845bbls – a 55 per cent increase on initial estimates. Since then the company has installed a low capital cost modular production/processing facility and 1.6 kilometre pipeline for Rex-1, which began pumping fluids (via a downhole pump) at the start of June and achieved an interim flow rate of 275bopd after just 10 days. As it stands, the well is now producing 200-225bopd with oil delivery at 99.5 per cent purity. If all goes to plan, work on the proposed 1500m deep Rex-3, which will have a lateral target length of 2000m and the potential to yield up to 400-500bopd, should start sometime in November. Once Rex-3 is established, the company will enjoy the option of increasing its interest in the entire Wizard Lake field to 50 per cent. Under this farm-in arrangement with Point Loma, it will pay 100 per cent of the well costs, but receive 75 per cent of well income until the carried costs have been recovered. According to Whitebark Energy managing director David Messina, the company originally looked to Canada after its onshore Warro gas JV in Western Australia was put on care and maintenance due to a WA Government moratorium on fracking. Located 200km north of Perth in the Perth Basin, the Warro gas field contains anywhere between 4.4-11.6 trillion cubic feet of gas. While the fracking impost has now been lifted in areas with existing petroleum licences – and further field appraisal work at Warro is expected to be reignited sometime in 2020 – Whitebark has absolutely no regrets regarding its overseas expansion. “Wizard Lake is in a low risk tier-1 oil and gas jurisdiction – the highly productive and prospective province of Alberta is the world’s third largest province when it comes to reserves,” Messina said. “It has produced 3.3 million barrels of oil and 11 billion cubic feet of gas a day, so we have definitely established ourselves in the right neighbourhood. “Our project also sits near some substantial infrastructure, with refineries located just 25 kilometres away by road, so we know our operating costs will be low and our margins robust.” Messina said previous producers had overlooked Wizard Lake during the 1950s and 1960s because they were chasing deeper reef pools. Further opportunities exist in Alberta and Whitebark is now well placed to expand further in the basin following its success at Wizard Lake.
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Leigh Creek Energy Limited
Central Petroleum Limited
Plans by this Adelaide-based junior to enter South Australia’s energy sector were given a significant boost earlier this quarter when the market injected over $3 million into its flagship project. During August, Leigh Creek Energy (LCK) confirmed it had secured approximately $3.2 million (before costs) from institutional, sophisticated and professional investors to advance what is currently the country’s largest uncontracted gas reserve available to east coast customers. Using in situ gasification (ISG) technologies, the company plans to convert remnant coal resources into synthetic natural gas (syngas) and/ or ammonium nitrate products (fertilisers and explosives) at its South Australian Leigh Creek Energy Project (LCEP), where economic flow rates (1 million cubic feet of syngas per day) have already been established via environmentally-compliant pre-commercial demonstration work at the site earlier this year. Located 550 kilometres north of Adelaide, the LCEP currently has a maiden 2P reserve of 1,153 petajoules. According to LCK, potential markets for this asset include pipeline gas (888PJ), ammonia (31 million tonnes), urea (53Mt), diesel (8 billion litres) and electricity (246,783 gigawatt hours). The company is seeking an agreed pathway towards commercial ISG development with the state government, and is confident the project will provide both long term stability and economic development opportunities in regions like the Upper Spencer Gulf and northern Flinders Ranges. According to LCK’s managing director Phil Staveley, strong share market performance also indicates growing investor recognition of the fledging energy player’s commercial abilities. “This capital raising continues to demonstrate strong support for the company and its plans to commercialise the large gas reserve at the LCEP,” he said. “With its maiden gas reserve, LCK is poised to expand exponentially in the near future.”
Having tapped into the lucrative east coast energy market earlier this year, Brisbane-based Central Petroleum (CTP) is entering its next growth phase as it ups its exploration ante while focusing on operational performance at its three Northern Territory gas fields. The company not only finished the June quarter with improved gas sales, a robust cash flow and a solid bank balance, but in July also announced plans to establish 2C resources for its Project Range Joint Venture in Queensland’s Surat Basin prior to any pilot well production testing. Along with 50:50 JV partner Incitec Pivot, CTP is targeting the coal seam gas (CSG) potential of the highly prospective Walloons coals. Meanwhile, drilling has resumed at its Dukas JV (with Santos as the 70% farm-in partner) in the NT, where the focus is on sub-salt closures in the southern Amadeus Basin. Although success at either project could see CTP expand its east coast market, it believes Dukas - given its potential size - could well be a company changer. Not that CTP hasn’t already been going through a few significant developments in 2019. At the end of January it hooked up with the 622 kilometre Northern Gas Pipeline, a transformational infrastructure project linking Tennant Creek with Mount Isa. This helped CTP sell four petajoules of gas for $19.5 million (net of gas purchased and sold) during the June quarter – an 8.6 per cent increase in sales over the March reporting period – with the bulk of this production coming from its Mereenie and Palm Valley fields in the NT. This cash flow ensured the company finished the financial year with $17.8 million in the bank – funds which can be channelled into further growth opportunities.
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Talon Petroleum Limited
Being in the right address pretty much sums up Talon Petroleum’s corporate strategy as it consolidates its presence in the UK North Sea. During the June quarter the Perth-based company completed the acquisition of EnCounter Oil, giving it unfettered access to the highly prospective Skymoos and Rocket prospects. Then, in late July, Talon announced two new developments regarding further holdings in the area. First, it was granted (in a joint bid with ONE-Dyas E&P) a licence over Block 14/30b, wherein lies the Thelma, Louise and Buffalo prospects. Best estimates for these targets are currently 29 million barrels of oil, 17mmbbl and 160 billion cubic feet of gas respectively. Second, site survey activities over the proposed location of the Curlew-A appraisal well – in which Talon has a 10 per cent interest – was started on Block 29/7b by Corallian Energy. Currently, Curlew-A’s gross 2C contingent resource for recoverable oil is 36.2mmbbl. According to Talon managing director Matt Worner, this acquisition was the company’s first piece of operational work since it established its UK North Sea strategy in 2018. Moreover, it is deemed significant given it contains an estimated discovered resource of 39mmbbl and is close to nearby infrastructure. Despite these developments, it’s the EnCounter acquisition which has arguably generated the most excitement amongst investors during 2019. As it stands, Skymoos – which is a direct analogue to the Upper Jurassic Buzzard Field (the UK North Sea’s largest producing oil field) and is on trend with several developed oil and gas discoveries – has a best estimate prospective resources of 107mmbbl. Meanwhile Rocket, with its potential resource of 27mmbbl, is a direct analogue to amplitude-supported oil fields to the north east.
If all goes to plan, Melbourne-based FAR Ltd may have made a final investment decision regarding the development of its world class SNE project off the coast of Senegal by this time next year. And assuming funding is put in place over the coming 10 or so months, it’s possible the West African offshore field will yield its first
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THE LOGO VERTICAL.
oil by the end of 2020. Market interest in FAR’s MSGBC (Mauritania, Senegal, GuineaBissau and Conakry) Basin holdings certainly hasn’t waned since it discovered SNE-1 and Fan-1 in 2014. During the June quarter the company raised US$31.5 million ($45 million domestically) through a private placement to complete front end engineering studies and reach the final investment decision for the SNE development. Monies from this raising will also go towards the planning and purchase of the long lead items for drilling in The Gambia and Guinea Bissau in 2020, as well as finalising the seismic acquisition, processing and interpretation of the new seismic data in its North West Shelf permit (which sits in the Dampier sub-basin off the coast of Western Australia). As it stands, SNE – which has attracted farm-in partners Cairn Energy and Conoco Phillips - is estimated to produce 230 million barrels of oil and 200 billion cubic feet of gas in its first phase of operations, equalling 265mmbbls oil equivalent (with 39.7mmboe net going to FAR). On the current P50 full field basis, FAR will net 105 mmboe with tremendous potential upside from better recovery of the key reservoirs (currently estimated to be 10% when global analogies for these reservoirs produce in the range of 15-30% recovery) and tie backs of nearby discoveries already made by the Joint Venture.
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Triangle Energy (Global) Limited
Norwest Energy NL
With a healthy cash flow coming from its dominant holding (78.75%) in the offshore Cliff Head project in Western Australia, Triangle Energy (Global) has been able to chase further growth opportunities in the Perth Basin. The company has its eye on the prospective Xanadu oil field and is now awaiting the results of a recently conducted 40 square kilometre 3D seismic program. Located offshore about 270km south west from the WA coastal town of Dongara - and 14km south of the Cliff Head oil field Xanadu is a joint venture between Triangle (45%) and Norwest Energy. Triangle is also completing the necessary approvals for the onshore Mt Horner l7 production licence, in which it holds a 50 per cent interest with farm out agreement partner Key Petroleum. The PL overlies the Allanooka Terrace in the North Perth Basin (and is adjacent to the prolific Dandaragan Trough). So far, multiple “attic” locations for infill development wells have been identified. The JV partners now anticipate conducting a 50sqkm 3D seismic survey and drilling at least two in-fill development wells as soon as possible. Additionally, the WA-based Triangle is looking at another growth opportunity – this time in Queensland’s Bowen Basin via its 35.47 per cent interest in State Gas, 80 per cent owner of the prospective Reid Dome gas project. In 2018, two wells – Primero West 1 and Nyanda-4 - were successfully drilled, with the 1200 metre deep Nyanda encountering 40.4m of net coal seams as well as 25m of separate carbonaceous shales and thinner coal seams. During the June quarter Cliff Head generated revenues of $6.89 million for project operator Triangle – a $760,000 increase over the March period due to higher production.
Like other Perth Basin explorers, Norwest Energy is reviewing the oil and gas prospectivity of its Western Australian onshore portfolio in light of the Waitsia gas discovery. In particular, the company is approaching its 10.1 square kilometre Springy Creek oil prospect - which sits in the northern part of its EP368 Joint Venture (with Energy Resources) some 30km north east of Dongara - with renewed enthusiasm, and is now confident its geological chance of success is 25 per cent. During July Norwest told the market that Waitsia, located 5km to the west of EP368, had “opened up an exciting new petroleum play within the basin by encountering a very significant hydrocarbon accumulation within the Lower Permian Kingia and High Cliff Sandstone formations”. “The prospect offers significant potential for sizeable oil accumulations within both the Kingia and the High Cliff Sandstone formations which, based on well intersections in the wider region, are prognosed to incorporate thick, high-quality reservoir sand units at the prospect location at target depths of 2,470 metres and 2,570m respectively,” it said. The greater Springy Creek structure, encompassing the southern and northern culminations, is an elongate north-south trending three-way dip closure with fault closure to the south. Reservoirs within this structural feature could be sourced by oil migrating from the proven Kockatea Shale oil kitchen to the south. Furthermore, the prospect is situated within a structural setting comparable to that of the Mt. Horner oil field 15km to the west. In terms of its Perth Basin offshore activities, Norwest – along with Triangle Energy (Global) – is conducting a 3D seismic survey of its Xanadu oil discovery 300km north of Perth. Results for this work should available by October.
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Vintage Energy Limited
Bass Oil Limited
Vintage Energy Ltd is a recently listed petroleum company focused on exploration and appraisal of underexplored but highly prospective acreage. Reg Nelson (former Managing Director of Beach Energy Ltd) and Neil Gibbins (former Chief Operating Officer of Beach Energy Ltd) believed that an opportunity existed to build a genuine exploration and appraisal business with the backing of a management team that has an outstanding record of petroleum discovery success in Australian onshore basins. With the adoption of a prudent approach to investment, namely the acquisition of high potential acreage close to infrastructure, Vintage has set itself up to deliver value accretive growth for its shareholders. The management team at Vintage has already built an enviable portfolio of permits that offer the potential for hydrocarbon discovery and, once successful, rapid development and early cash generation. The current portfolio of onshore exploration and appraisal permits are located in the Galilee Basin (Queensland), Cooper and Eromanga Basins (Queensland), Otway Basin (South Australia and Victoria) and the Bonaparte Basin (Northern Territory). A two well program recently commenced in the Galilee Basin with the spudding of the Albany-2 well. This program is a follow up to successful gas flows from Albany-1 last year and is targeting conventional sandstone reservoirs within the areally significant Albany Field. Drilling this year is also expected within our Cooper/Eromanga Basins and Otway Basin permits. These permits are well located with respect to the east coast gas market, local mines and industry. Vintage will continue to add to its current portfolio of high-quality gas permits with a focus also on oil, which is particularly relevant given the history of the Vintage team in discovering and developing the oil fields of the Western Flank in the Cooper / Eromanga Basins.
Earlier this quarter Bass Oil achieved a significant milestone in its Indonesian growth strategy by finalising its 55 per cent operator interest in the Tangai-Sukananti licence in the prolific South Sumatra Basin. The oil producer completed its last payment of $770,000 (plus interest) to Cooper Energy after initiating the $2.27 million deal in February 2017. According to Bass managing director Tino Guglielmo, the company – which is now debt free - is confident of drilling its first development well, Bunian-5, in October this year and doubling its Tangai field output to 1,400 barrels of oil per day (bopd). It will also continue to pursue its business development program via a three-tiered strategy designed to create and maximise value. This involves acquiring company-transforming assets, embracing material growth exploration opportunities and optimising existing mature fields using proven technologies. During the June quarter Bass’ net oil production was 34,022 barrels at an approximate gross daily production of 680bopd. This rate increased to 780bopd in June following pump repairs. The company finished the quarter with US$770,000 in the bank, and is currently raising another $2,681,167 through a rights issue to help fund the low risk Bunian development. Gugliemo said being debt-free would assist with the active evaluation and negotiation on a number of on and offshore Indonesian opportunities as Bass looked to expand its oil portfolio during 2019. “After several years of successful proven Indonesian operatorship, Bass is highly regarded in-country and has formed deep and strong relationships with local operators and is well known by the Indonesian upstream oil and gas regulator,” he said. Bass’ plans include establishing itself as a mid-tier oil and gas producer (2000-5000 estimated bopd) as soon as possible.
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Metgasco Limited (ASX: MEL)
Cooper Energy Limited (ASX: COE) Emerging gas producer Cooper Energy has flagged a transformational year for 2020 following completion of the Sole offshore gas field development in 2019. Production from the field is expected to increase the company’s daily gas production from 15 terrajoules per day (TJ/day) to over 80 TJ/day, bringing substantial increases in sales and cash flow. Sole is expected to come online in the December quarter of this year after APA Group completes commissioning of the Orbost Plant upgrade. Cooper Energy managing director David Maxwell said construction of the offshore field development for Sole was a highlight of the company’s 2019 results. “We completed construction of our flagship project safely, and within budget,” Maxwell said. “We look forward to commencing production and a transformative uplift in cash flow from Sole gas supply very soon. “However, it is important that keen anticipation not overlook the significance of an outstanding project performance.” The start-up of production from Sole is one of a number of events scheduled for what looms as an landmark year for Cooper Energy. The company has planned its largest exploration program yet, with gas exploration in its offshore and onshore Otway Basin permits and up to 19 wells by the PEL 92 Joint Venture in the Cooper Basin. Maxwell said the company is also preparing its next offshore gas drilling campaign which, subject to rig availability, could commence in late 2020. “Our portfolio holds undeveloped gas reserves and resources such as at Manta and Henry which, subject to drilling, can be brought to market,” he continued. “These projects, and any discoveries that result from our current offshore drilling campaign, can bring the next wave of growth for our company after Sole.”.
Investors will be closely watching a farm-out arrangement ASX-listed Metgasco recently made with another Australian player involving some highly prospective onshore Queensland acreage in the Cooper-Eromanga Basin. The deal – with Vintage Energy – covers the 370 square kilometre Authority to Prospect 2021 permit, which contains drill-ready prospects identified by 3D seismic and sits just 20 kilometres from established oil and gas fields (with associated pipelines and facilities) that historically have yielded over 600 billion cubic feet of gas and 11 million barrels of oil. Under the terms of the agreement, Vintage will earn a 50 per cent interest (and operatorship) in the licence by funding 65 per cent of the first exploration well drilled (up to a maximum cost of $5.3 million, with its share being up to $3.445 million), reimbursing 65 per cent of past licence exploration costs ($527,800) or carry Metgasco for the first $527,800 of exploration costs, as well as injecting up to $70,000 into 2D/3D seismic re-processing currently scheduled to better identify expected shallow oil targets on the block. This JV provides Metgasco with several key benefits. First, Vintage’s team is well regarded by the company’s board and has Cooper Basin technical and operational experience. Second, the agreement secures additional project funding to deliver drilling of one exploration well in 2019. Third, Metgasco and Vintage have agreed to consider other potential areas of mutual interest. Planning to drill the Vali prospect, a robust anticline with dual primary targets of the Toolachee and Patchawarra Formations sitting adjacent to the hydrocarbon-rich Nappamerri Trough, has started. The closest well, Kinta-1, is around 3km to the north, where gas-charged sands have been intercepted in both the Patchawarra and Toolachee intervals.
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Strata-X Energy Limited
Over the past few years the United States has again become energy efficient thanks to enterprising companies like ASX-listed Sacgasco. With its underlying strategy to find and develop opportunities in overlooked areas that sit close to under-supplied oil and gas markets with attractive product prices, Sacgasco has established itself as a growing natural gas player in northern California’s onshore Sacramento Basin. The company currently has varying working interests (10-100%) in 11 projects – six of which have gas-producing wells. With the exception of one (Willows Gas Field) it is the operator. During the June quarter the company not only increased its gas output in a market where prices remain at a premium, but it progressed two of its exploration and appraisal programs. The first was its 46 per cent-owned Borba (formally Anzus) gas project, where a location for a prospect well was identified. Located along the Dempsey Trend, and less than two miles from existing gas pipelines, the vertically stacked conformance of seismic anomalies is much greater than at the Dempsey 1-15 well (Sacgasco 60%), where 4,000 feet of gas saturated sediments were found when drilled. Aside from the fact Borba sits within a 3D seismic data volume, an undrilled amplitude anomaly suggests gas-filled sands will be intercepted in the shallower Forbes Formation by the well. Meanwhile, Sacgasco is also seeking regulatory approval to re-enter its 50 per cent-owned Alvares 1 natural gas play so it can sequentially evaluate casing integrity and potentially test interpreted gas-filled reservoirs. Alvares is nine miles from large pipeline infrastructure and is on trend from the similarly structured Sites Anticline on which the 1948 Shell James 1 well flowed gas to surface from reservoirs of a similar age.
A dual–listed energy player looks set to start drill testing one of Africa’s largest undeveloped coal bed methane (CBM) resources within the next six months. During August the US-based Strata-X Energy said Botswana’s government had approved the form and scope of its new Environmental Impact Assessment for its onshore Serowe CBM project. This documentation should be submitted sometime in September, with possible final approvals in place by December. Following this, the company can drill and test up to 75 wells covering three prospecting licenses within the Serowe Fairway’s high-grade zone. Denver-based Strata-X currently holds 4784 square kilometres over the project area, which has a certified prospective resource of 6.05 trillion cubic feet of natural gas. The high-grade zone covers around 1295sqkm and spans five wholly-owned licenses. It is interpreted to contain 10 metre (average) net bright-coal seams over a 50m interval with high gas saturations up to 100 per cent and a 2.38 Tcf prospective gas resource net to Strata-X This interpretation is reinforced with the results of the company’s 19B-1 well and historic core hole data, where bubbled free gas from the targeted bright coals were observed. The area immediately surrounding Strata-X’s recently drilled and logged 19B-1 well was certified to contain 2C contingent resources of 23 billion cf of gas. According to Strata-X, its focus on the high grade area will be a major growth driver. A multi-well appraisal drilling and production testing program within this area that steps out from 19B-1 is being planned and tendered. This proposed program will upgrade prospective resources to contingent resources. It will also see the production testing of wells to acquire fluid flow rate data.
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Cue Energy Resources Limited
Invictus Energy Limited
Having successfully established cash-generating operations in Indonesia and New Zealand, Melbourne-based Cue Energy now looks set to capitalise on its assets in Western Australia’s prospective Carnarvon Basin. During the June quarter Cue Energy Resources announced it had entered a Joint Venture with BP Developments Australia (42.5%), Beach Energy (21%) and New Zealand Oil & Gas (15%) to drill the Ironbark-1 well, which sits offshore in EP WA-359-P some 50 kilometres from the North West Shelf ’s liquefied natural gas infrastructure. The Ironbark prospect presently has a best estimate of 15 trillion cubic feet of prospective gas. Given this, Cue – with its 21 per cent stake in the project – could be onto a company changer, significantly adding value to a business model which has already achieved a considerable amount of success. It is now expected Ironbark-1 will be drilled to 5500 metres sometime in 2020, with BP being operator. Aside from $1.8 million received for the WA farm-in partners, a further US$8 million was escrowed by Cue to fund the uncarried portion of its budgeted participating interest cost for the well. This came on top of the $9.4 million generated during the June quarter from its offshore fields in New Zealand (Maari and Manaia) and Indonesian (Oyong and Wortel), where the combined net production for the three months was 31,504 barrels of oil and 362 million cf of gas. Cue’s oil sales were 52,991bbl - up from the previous quarter - at an average of $103.45/bbl (US$72.23/bbl). Meanwhile, it sold 377Mcf of gas at an average of $10.42/thousand cf (US$7.28). As a result the company finished the quarter with $26.19 million in the bank and was free of debt.
Invictus Energy has found itself in elephant country, with the proverbial pachyderm leading it to the giant Cabora Bassa project in Zimbabwe. In early July the company announced the resource potential of its Mzarabani prospect – a multi-trillion cubic feet and liquids-rich conventional gas-condensate target which sits within its 80 percentowned and operated SG4571 permit – had grown considerably following the release of an independent report by UK outfit Getech. The net mean recoverable conventional potential of the massively-stacked Mzarabani is now 1.3 billion barrels of oil equivalent consisting of 6.5 Tcf and 200 million barrels of condensate net to Invictus. Meanwhile, the estimate for the primary Upper Angwa target within Mzarabani has increased to 4.4 Tcf and 187mmbbl of conventional gas-condensate on a gross mean unrisked basis. In addition, the newly identified Msasa prospect, a substantial structural prospect within SG4571 which is also a stacked anticline feature, is estimated to contain 1.05 Tcf and 44mmbbl of conventional gas-condensate (also on a total gross mean unrisked basis). Invictus is now confident it is sitting on the largest, undrilled seismically defined structure onshore in Africa. “The substantial work undertaken to integrate the geological and basin modelling studies with the reprocessed and interpreted gravity, magnetic and seismic datasets has enabled us to characterise the subsurface in more detail and identify and quantify the additional prospectivity,” the company’s managing director Scott Macmillan said. “This has not only materially enhanced the value of our acreage, but also de-risked it.” The company has since engaged the UK-based ENVOI, a leading acquisition and divestiture adviser for the international upstream oil and gas industry, to run the farm out process for SG4571.
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Australian Eastern States gas market study and unconventional play atlas RISC has developed a comprehensive Australian Eastern States Unconventional gas market study. The study is based on the 2P reserves positions for domestic gas producers paired with a range of gas demand forecasts to identify probable supply gaps on the East Coast over the next 10 years. The study has analysed all of the potential sources of unconventional gas to fill the East Coast market gap and determines likely gas supply rates, development schedules and breakeven supply costs for each of the major demand centres. The report illustrates the required gas prices to drive unconventional gas development in Eastern Australia, the subsequent scale of new unconventional gas supplies to the forecast gaps in the market and describes how those developments could reverse the trend of rising prices over time. The study includes an east coast gas market model which mirrors the market. Supply sources are modelled at the basin level and have been characterized using known reserves, production capacity and cost of supply data.
Demand has been aggregated into â€œdemand centersâ€? which are mostly the large population centers on the east coast of Australia as well as the Curtis Island LNG projects. The model forecasts supply and estimated gas prices for the input demand forecasts. Gaps in the existing supply forecast can be utilised by new sources of unconventional supply if the market price can be met. Deliverables: The Eastern Australia unconventional play atlas and market study is available for purchase in a hyperlinked .pdf report for A$50,000. An optional ArcGIS project is available for an additional A$15,000. The Eastern Australia gas market study is available as an optional Excel model for A$10,000. Permit specific unconventional resource estimates can be supplied on a case by case basis from the basin wide studies.
Phone +61 8 9420 6660 Email Ian.email@example.com Joe.firstname.lastname@example.org Web www.riscadvisory.com
Resource play quantification using common recovery segment mapping
Buru Energy Limited
Elixir Energy Limited
This Western Australian oil producer with considerable land holdings in the state’s Canning Basin has returned promising results from the first exploration well in its 2019 drilling campaign. In mid-August ASX-listed Buru Energy said its Adoxa 1 play which sits in EP428 next to the company’s flagship Ungani Oilfield in the state’s south west Kimberley region - revealed potential oil flow between 1891-1902 metres (the 1900 level) following extensive wireline logging and pressure testing over the well’s open hole section. Located on the regionally significant Yakka Munga structure, Adoxa 1 has been drilled to 2300m by Buru and its 50:50 Joint Venture partner Roc Oil Company. The JV’s principal target is conventional oil from the Reeves Formation. So far the partners are confident the mostly-unexplored Reeves section of Adoxa 1 is over 700m thick. According to Buru, the well - which was spudded on July 24 - has provided some very valuable regional information, revealing thick shale sealing units which have not been seen elsewhere in the basin, as well as a number of well-developed reservoir sand units. Moreover, other prospects identified on the 3D seismic that are smaller than the Yakka Munga structure have been upgraded in light of Adoxa 1’s results. “The fact that hydrocarbon shows were encountered at a number of levels and there is a potentially producible reservoir in the well at the 1900 level has also validated the petroleum system,” Buru said. Meanwhile, oil output from the Ungani JV (also a 50:50 JV with Roc) continues to average 960-1000 barrels per day (gross) with volumes soon expected to increase when Ungani’s 6H and 7H wells are brought into production.
Adelaide-based Elixir Energy has one primary goal – to establish Mongolia’s first gas discovery as soon as possible. During August the ASX-listed junior said it had signed a binding drilling contract with Mongolian outfit Erdenedrilling to drill two fully-tested coal-bed methane (CBM) core holes at its wholly-owned Nomgon IX CBM PSC project, which sits close to the Chinese border in the country’s South Gobi region. Covering 30,000 square kilometres in a coal-bearing sedimentary basin, Nomgon has a prospective resource with best gas estimates of 40.1 trillion cubic feet of gas (unrisked recoverable) and 7.6Tcf (risked recoverable). Elixir is now confident the first well will be spudded in or around late September/early October. If all goes to plan it will be the first CBM one in the country to be tested using international best practice gas industry standards. Earlier this year the company took a number of significant steps towards achieving its primary goal. Aside from receiving final regulatory approvals for its exploration program from the Mongolian Government, it completed a 2D seismic acquisition that will underpin a program focusing on de-risked leads as identified by ongoing geological work. Elixir also strengthened its management team with the appointment of industry veterans Richard Cottee (the former managing director of Queensland Gas Company) as its non-executive chairman and Stephen Kelemen (who ran Santos’ coal seam gas group in QLD) as a non-executive director. In addition, the company raised $3.6 million (before costs) via a share placement, ensuring it finished the quarter with around $4.3 million in the bank and no debt. The initial drilling should determine coal thickness while delivering a comprehensive testing program focused on measuring gas content, gas composition and permeability.
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Tap Oil Limited
Galilee Energy Limited
Perth-based Tap Oil continues to implement its Thai growth strategy. In August the company announced it was maximising its offshore Manora Oil Field assets in the Gulf of Thailand via the drilling of three development wells (MNA-22H, MNA-23H and MNA-24H) from the Manora platform. Both MNA-23H and MNA-24H – which will provide horizontal production points in the 300 series sands (the 370-90 and 370-10 reservoirs respectively) that were found in the 2018 Manora-8ST appraisal well - reached a total depth of 2216 metres. Petrophysical interpretation of well logs in MNA-23H showed a total pay penetrated in the horizontal lateral of 197.8m with an average 30 per cent porosity. This horizontal lateral was completed with a sand screen and electrical submersible pump, with the well test returning 945 barrels of oil per day and 15 per cent basic sediment and water. Meanwhile, corresponding numbers for the identical MNA-24H were 155m with 28 per cent porosity and 1033 bopd and four per cent BSW. Since then work has started on MNA-22H. The Manora Joint Venture covers the G1/48 concession which has been a cash cow for 30 per cent-owner Tap and its partner/operator Mubadala Petroleum (Thailand). During the June quarter the JV generated sales worth around US$11.8 million on the back of 5284 bopd production. The WA company subsequently finished the financial year with US$31.54 million in the bank. In addition, Tap continues to streamline its non-operated Australian assets in the Carnarvon and Bonaparte basins so it can sharpen its focus on Manora. It has also hedged 165,938bbl of Manora crude (to be lifted between May and December) to protect itself against any price falls of US60/bbl while retaining exposure to an average price increase up to US$77/bbl.
Over the past six months ASX-listed Galilee Energy has strengthened its position as one of the leading uncontracted gas resource holders operating on Australia’s east coast. As a result the company now looks set to play an integral role in supplying Queensland’s energy market from the early 2020s. In August Galilee announced it had received operatorship, and a full working interest, in Authority to Prospect (ATP) 2043 - which overlaps the Surat and Bowen basins - for six years. Covering 384 square kilometres within the world-class Walloon Subgroup coal seam gas (CSG) fairway and the oil and gas prone eastern flank of the Taroom Trough in the Bowen Basin, this acreage contains 504 petajoules of CSG 2C contingent gas resources (in the Walloon Subgroup). Meanwhile, the company continues to develop its wholly-owned Glenaras Gas Project (GGP) in the Galilee Basin, a mature 4000sqkm exploration play in ATP 2019 on which $90 million has already been spent defining a resource. GGP’s assets include a 450 megalitre water storage facility (costing over $6 million) as well as existing production gathering and flare facilities. Galilee said GGP’s current multi-lateral pilot program had seen the drilling of Glenaras 14L, 15L and 16L, where strong initial productivity was observed during commissioning. Combined with observed pressure responses in the flanking laterals of Glenaras 10L and 12L, the excellent productivity and connectivity of the targeted R3 coal seam was confirmed. As it stands the contingent gas resource (CGR) within the Betts Creek coals are a 1C of 308 PJ, a 2C of 2508 PJ and a 3C of 5314 PJ. With ATP2043, Galilee’s 2C CGR has increased to a material 3012 PJ.
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Sun Resources NL (ASX: SUR) Sun Resources is an oil and gas exploration and development company that is focussed on delivering value across several opportunities in Louisiana, United States. The company is targeting assets that it considers will be commercially viable in the current low oil price environment. Sun Resources’ current focus is in Louisiana on the Bowsprit oil project. Sun secured the Bowsprit project in 2017 in Joint Venture with Pinnacle Exploration and has recently announced it would be acquiring the latter’s 50 per cent interest in the project, moving to a 100 per cent working interest. Sun had paid 100 per cent of the initial Bowsprit leasing costs and had progressed the technical studies and development planning without any financial contribution from Pinnacle. Sun has been intent to drill the first well on the project as soon as practical, however it was impractical to progress to the drilling phase until both parties secured the necessary funding. Subsequently, Pinnacle has opted to accept an offer from Sun to purchase its interest in the leases rather than fund a well. The deal means Sun has cleared a path toward drilling of the first Bowsprit well. The technical work carried out to date on the Bowsprit project has directed the company to drilling a horizontal well, drilled between two vertical, former oil production wells as its preferred approach. Advisory group, RISC, has estimated such a well could produce at an initial rate of up to 2,000 barrels of oil per day (bopd). If the appraisal well is as successful as anticipated, Sun has indicated it would be suspended as a future producer, with a view to bringing the field on production in 2020.
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Samson Oil & Gas Limited (ASX: SSN) Samson Oil & Gas is an Australian-based oil & gas company holding extensive development and exploration acreage in the United States of America. Most of the company’s recent news has emanated from the company’s 87 per cent operated average working interest in the Foreman Butte project in North Dakota that hosts the Home Run Field, the largest areal oil field in Samson’s portfolio. This was developed on a 640-acre spacing pattern, from which the company’s engineering and geologic analyses determined that only 3.2 per cent of the original oil in place has been recovered to date. Given that oil fields typically recover up to around 20 per cent of their oil in place, Samson considers there would appear to be a healthy supply of un-developed oil to be recovered from this field. In its June Quarterly, Samson reported the first well of its infill development program, the Gonzales 1-8H well, had achieved a measured total depth of 11,736 feet and lateral length of 2,062 feet within the Ratcliffe reservoir. Although the lateral length was less than planned, it did offer an opportunity to test the reservoir’s oil productive capacity. At time of writing, the well had recovered a total of 57 barrels of oil. In preparation for drilling this well, Samson injected around 20,000 barrels of saltwater and then used 2,600 of barrels of fresh water during the drilling process. Before the oil cut appeared, early fluid had a density of 1.13 that increased to 1.15 indicating the produced fluid was approaching the 1.2 density that represents formation water. The oil cut after the initial arrival of oil, has averaged 4.5 per cent..
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Merger and Acquisition Evaluation Field Simulation, Development and Management Reserves and Resources Auditing Equity Valuation and Determination Exploration Prospectivity and Portfolio Analysis Risk and Uncertainty Modelling Expert Witness, Unitisation and Redetermination Unconventional and Alternative Energy
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OVER 40 YEARS OF GLOBAL EXPERIENCE
Warrego Energy Limited (ASX: WGO)
Carnarvon Petroleum Limited (ASX: CVN) Carnarvon Petroleum Limited recently completed a $79 million fully underwritten institutional placement. “The proceeds provide Carnarvon the opportunity to progress the Dorado project through to the development phase and will also support the company’s other key strategic initiatives,” Carnarvon Petroleum managing director Adrian Cook said. The company wasted little time getting the cash out into the field by commencing drilling of the Dorado-3 appraisal well. The Dorado-3 well is the second appraisal of the Dorado oil and gas field, which Carnarvon Petroleum discovered in 2018. The Dorado field is located approximately 160 kilometres northnortheast of Port Hedland in Western Australia in the Bedout Sub-basin in around 95 metres water depth. The Dorado-1 exploration well discovered hydrocarbon bearing reservoirs in the Caley, Baxter, Crespin and Milne Members of the Lower Keraudren Formation. The Dorado-2 appraisal well, located around 2.2km north east of the Dorado-1 well, confirmed hydrocarbon bearing reservoirs in the Caley, Baxter and Milne and importantly demonstrated connectivity within each reservoir between the two wells. The Dorado-3 appraisal well is located approximately 900m north west of the Dorado-1 discovery location and has been designed to enhance the Joint Venture’s confidence in the subsurface characteristics and confirm reservoir productivity. Dorado-3 is planned to conduct two, and potentially up to three, flow tests targeting the Caley, Baxter and Milne reservoirs, as well as acquire approximately 380m of full-bore core in the Caley, Baxter, Crespin and Milne Members. This will result in a healthy amount of new data to further characterise the Dorado field. The Dorado oil and gas field resides in WA-437-P in which Carnarvon holds a 20 per cent interest.
A $6.61 million capital raising has allowed Warrego Energy to advance its exciting EP469 onshore gas exploration joint venture in the North Perth Basin. Meanwhile, the ASX-listed company continues to establish an international project portfolio in order to diversify risk and access global funding opportunities. In terms of EP469, Warrego and 50 per cent JV partner Strike Energy have spudded the West Erregulla-2 (WE-2) well and now plan to drill it down to 5200 metres. Located some 300 kilometres north of Perth, EP469 contains extensions of the known nearby commercial plays in the basin, including the Waitsia gas field (the fifth largest onshore discovery in Australia) and Beharra Springs. Drilling at WE-2 will penetrate two independent reservoir targets, a secondary conventional gas target in the Basal Wagina sandstones as well as the primary gas sand sequence in the Kingia-High Cliff. So far, prospect evaluation from 3D seismic has yielded an extremely attractive, top tier, conventional structure in a combined dip and fault closure within the Kingia-High Cliff sequence similar to the productive zones in Waitsia. Initial assessment of the prospect suggests, if successful, it will be big enough to support a stand-alone development. While the Sydney-based Warrego is confident EP469 has the potential to be the most significant onshore well to be drilled in Australia during 2019, it is also moving forward with its Tesorillo conventional sandstone gas play in southern Spain. Comprising two petroleum exploration licences, the project is a JV between Tarba Energia (which is 85%-owned by Warrego) and AIM-listed Prospex Energy. Modelling work is underway to identify the location of a new gas well. If successful, it is expected this will be drilled sometime in 2020.
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Hazer Group Limited
Calima Energy Limited
Hazer Group Limited is an ASX-listed technology development company undertaking the commercialisation of the Hazer Process, a low-emission hydrogen and graphite production process. The Hazer Process takes natural gas and iron ore, two reasonably cheap feedstocks that are found in abundance within Australia. The process uses these to generate hydrogen and synthetic graphite, two products that are currently high in both value and demand due to their global market applications. “The core of our technology is the use of iron-ore as a low-cost catalyst for the gas decomposition reaction, which gives us a strong commercial advantage for accessing both hydrogen and high-quality graphite markets,” Hazer Group declares on its Web Page. The process recently generated excitement when Hazer Group’s partner Mineral Resources (ASX: MIN) produced high-quality graphite at its Paddle Tube Reactor (PTR) Pilot Plant. Hazer Group and Mineral Resources are developing a Mineral Resources owned and operated commercial scale synthetic graphite production facility based on the Hazer Process. This involves a three-stage development program: Stage 1 is the development of a pilot scale facility capable of producing one tonne per annum of high-quality graphite. Construction of this facility was completed in March 2019 and initial production runs under the pilot plant test program produced high-quality graphite with graphite product purity greater than 95 per cent TGC (Total Graphitic Carbon). “The graphite purity achieved is the highest we have recorded to date by the Hazer Process,” Hazer Group CEO Geoff Ward said. Mineral Resources will now undertake a detailed pilot plant test program of the PTR to establish the design and performance parameters of the commercial scale plant envisaged in Stage 2 and Stage 3.
Calima Energy is in a farm-in agreement involving oil and gas licences prospective for the Montney Formation in British Columbia (BC), Canada. The Farm-in Agreement allows Calima to acquire a working interest of up to 55 per cent in the Montney project and operatorship of the project. The company recently completed a three-well drilling campaign on its Calima Lands in BC, the results of which validated its early geoscience work, which predicted that the Calima Lands would be rich in gas, condensate (or light oil) and natural gas liquids. “Our target was to match the results achieved by our regional neighbours who are established producers,” Calima Energy managing director Dr Alan Stein said. “We believe our results show the potential to match or exceed the results of our immediate peer group.” Results from the drilling campaign demonstrated a 35 per cent Well Recovery Increase taking the estimated ultimate recover of each well to 8.4 billion cubic feet (Bcf) per well. Based on limited test results, the company conservatively estimated gas-to-liquids ratio conservatively estimated at 45 barrels per million cubic feet of gas (bbl/mmcf) with 65 per cent of the liquids being high-value condensate (priced at WTI). Calima expects the liquids ratio to increase once the wells are cleaned up and on steady production. Canada, and the Montney region, is a good place for an aspiring producer as it a global top five gas producer. The Montney accounts for almost half of Canada’ gas and is one of North America’s most productive and lowest cost resource plays. Production rates have been increasing in the region by 20 per cent per annum over the last three years.
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Melbana Energy Limited
Winchester Energy Limited
Melbana Energy’s most recent quarterly report made for exhaustive reading as the company advances projects in Australia and Cuba. Domestically, at the 100 per cent-owned Beehive prospect in the northwest of Australia, Melbana waited on Santos and Total for a decision to exercise their option to drill the Beehive-1 well. Santos completed an initial well concept select workshop and identified a provisional well design and progressed drafting of an Environmental Plan, which is targeted for completion by 3Q 2019. On the Block 9 project in Cuba, Melbana progressed discussions with CubaPetroleo regarding proposed modifications to the current work program timing and the requirement to provide a bank guarantee. A response is expected in the quarter ending 30 September 2019. Still in Cuba at the Santa Cruz Incremental Oil Recovery project, Melbana’s geoscience team continued technical work on opportunities identified for pursuit in the Santa Cruz IOR area. An approval process for the Incremental Oil Recovery PSC, which was agreed between Melbana and CubaPetroleo in late 2018, identified issues requiring further commercial clarification. Negotiation of these matters has commenced. Back on home soil at the Tassie Shoal Projects, the Tassie Shoal LNG project is a shallow water platform fixed to seabed design, low-cost development option for LNG production. The Tassie Shoal Methanol Project, with its ability to receive and process raw gas with a 30 per cent CO2 content, is an alternative development path. As it signed off the quarter, Melbana announced CEO Robert Zammit parted ways with the company, resulting in independent non-executive director Michael Sandy assuming interim executive responsibilities. Melbana also signalled its intention to make a takeover offer for Metgasco Limited (ASX: MEL)..
Winchester Energy is an Australian ASX-listed energy company that operates out of thewell-known oil region of Houston, Texas. Winchester Energy is focused exclusively on oil exploration, development and production in the Permian Basin of Texas where it has established initial oil production on its large 17,000 net acres leasehold position on the eastern shelf of the Permian Basin, the largest oil producing basin in the USA. Winchester’s lease position is situated between proven oil fields where the company has identified several prospects across its leasehold and is currently undertaking development drilling at the newly discovered Mustang Oil Field where the recently drilled its highly successful White Hat 20#3 that since has yielded initial production (IP) of 306 barrels of oil per day (bopd). A recent placement raised $2.5 million, enabling further development drilling activities at the Mustang Oil Field within the company’s Permian Basin leasehold position. “Recently drilled discovery well White Hat 20#3 at the Mustang Oil Field has already provided the Company with enhanced revenue in a short period,” Winchester Energy managing director Neville Henry said. “The next Mustang well will spud…and the company will also immediately commence completion activities at the recently drilled Arledge 16#2 well at the Lightning prospect which recorded a highly encouraging 45 feet of calculated net oil pay in the Cisco Sands.” Initial log calculations confirmed 20 feet of calculated net pay in the Lower Cisco Sand. Winchester will evaluate the interval, bottom up using conventional completion technology. Depending upon results from the Lower Cisco Sand test, the Upper Cisco Sand will be assessed to determine potential of this zone for recompletion and potential production comingling with the Lower Cisco Sands.
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Eon NRG Limited
Oilex Ltd’s flagship is the Cambay project, located in the State of Gujarat, India where the company is focused on commercialisation of the Cambay Field to capitalise on the large and growing natural gas supply-demand gap. The Cambay project is the most important component of the company’s portfolio, covering 161 square kilometres in the industrial heartland of India. Elsewhere in India is the Bhandut Field, located near the Lakshmi, Gauri and Hazira Fields that are producing oil and gas from reservoir intervals akin to those intersected in the Bhandut wells. The field was discovered and developed initially by ONGC of India. Hydrocarbons were found in Oligocene and Eocene sandstones and continued to be produced on an intermittent basis after the fields were acquired by the GSPC and Niko Joint Venture in 1995. Oilex recently expanded its Australian portfolio by increasing its interest in Petroleum Exploration Licenses (PELs) 112 and 444 licenses in the Cooper-Eromanga Basins in South Australia. The Licenses are situated on extensions of the Western Flank oil fairway, the most important recent contributor to oil production in the Cooper Basin. “Our recent review of the Cooper Eromanga basins has led us to focus on two specific play types,” Oilex managing director Joe Salomon said. “This acquisition provides good exposure to the very successful Jurassic hosted oil fairway. 3D seismic has been the key to the very high success rate in this play and we look forward to applying our access to specialised advanced technologies to the two existing surveys searching for new hydrocarbon pools. “Another added attraction is the low-cost associated with discovery and development in this area given that target depths occur at around 1,500 metres.”.
Eon NRG is an oil and gas exploration and production company focused exclusively on a portfolio of North American onshore assets. These include producing assets in Wyoming and California that provide strong cash flow, which in turn supports the exploration opportunities that the company considers to be presented by its expansive exploration acreage position in the Powder River Basin (PRB) of Wyoming. Recent work undertaken within at the PRB has involved substantial environmental, archaeological, and wildlife assessments as a precursor to Eon filing the permitting application for the company’s first well in the PRB, the Govt Kaehne #9-29. The company has sat down with more than 30 surface owners to negotiate surface access for this process. It also laid out a total of 52 listening survey stations to undertake assessments for the presence of Sage-Grouse. These wildlife assessments covered an area of more than 7,500 acres covering a two-mile radius of the proposed well location. Weather conditions didn’t help with late snow cover surrounding the proposed well location, delaying the conclusion of the environmental surveys. Eon applied for drilling to the Wyoming Oil and Gas Conservation Commission (WYOGCC) and the Federal Authorities, Bureau of Land Management (BLM), which were granted following the conclusion of Q2 2019. The company has a small but strategically located lease holding in Nevada which is focused on cobalt discovery which is in the early stages of exploration. Eon NRG’s Battery Minerals Division is positioning itself to take advantage of the growth in global battery energy demand through the low cost, staged exploration, discovery and development of battery mineral resources that are and will be required for current and future power, storage and distribution..
Strike Energy Limited (ASX: STX) Strike Energy claimed a major new gas discovery in August via its involvement in the Strike-Warrego Joint Venture in the Wagina sandstone as part of the West Erregulla-2 drilling campaign in the Perth Basin. The drilling demonstrated the Wagina sandstone to be some 74 meters plus in thickness and made up of sections of clean sand with interpreted blocky porosity development that was observed on drilling to have hydrocarbons present throughout. Since the discovery announcement, Strike has encountered additional gas bearing Wagina sands in the production hole section before reaching the Carynginia shale. Subject to logging, the company expects these to add a further five metres to the previously advised gross gas column, bringing it to 79 metres in total. The company considers the discovery analogous to Beharra Springs and its associated fields that were discovered during the 1990’s and early 2000’s with depths ranging from 3,270m to 3,870m and remain onstream and continue to produce sales gas. “When the results are compared to the those from Beharra Springs, the analogue is clear and favourable,” Strike Energy managing director Stuart Nicholls said. “This is a significant gas discovery given the observed and interpreted quality of the formation and over-pressured reservoir. “Our confidence is further enforced by the extensive analogue data from the Beharra Springs fields. “This includes the Redback South-1 well which is directly to the West and only 244 metres shallower which tested at 38mmscf/d. “This well and others are not only right next door but host a producing, conventional gas field in the same Wagina sands in the same basin. “Strike is looking to deliver on further outcomes from WE-2 as predicted in the Strike geological model.”.
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Real Energy Corporation Limited (ASX: RLE) Real Energy is gas development company with a focus on Queensland, primarily in Australia’s most prolific conventional onshore petroleum producing basin, the Cooper basin where the company has 100 per cent ownership in permits ATP 927P and ATP1194PA. Most recent activity has centred on the company’s Windorah gas project where it has continued to progress exploration and development activities. These have included extended flow tests that recorded sustained and continuous rates for both wells tested Tamara 2 and Tamara 3. Although the rates were lower than what had previously been recorded, the Tamarama 2 well achieved a sustainable flow rate ranging from 0.4 million standard cubic feet per day (mmscfd) to 1.3 mmscfd. These rates were dependent on back pressure and choke size settings (between 6/64 to 10/64 inches). Both wells will be put on production once the pipeline between Tamarama and Mt Howitt is built. The Queensland Government has granted a pipeline licence between the Tamarama producing wells and the Mount Howitt facility operated by Santos Limited. Real Energy drilled the Tamarama 2 and Tamara 3 gas wells as follow-up wells subsequent to the company’s initial discovery well of Tamarama 1. They were drilled utilising a changed deviated wellbore design with optimal stress orientation for more efficient fracture stimulation. As a result, Tamarama 2 and 3 have yielded an improvement in the well performance compared to Tamarama 1. Real Energy anticipates more improvement with future wells especially from an enhanced stimulation process and using different proppant sizes as it expects these extraction techniques to evolve and thus yield better future flow rates. Real Energy has every confidence in the potential of the Windorah Field.
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Otto Energy Limited (ASX: OEL) Otto Energy returned to oil producer status in 2018, commencing production from the company’s 50 per cent-owned SM 71 oil field in the Gulf of Mexico. The company is using the cash flow from SM 71 production and the anticipated production from the recently discovered Lightning well in Matagorda County, Texas where production is imminent. The most recent news emanated from the Green Canyon 21 lease farm-in venture in the Gulf of Mexico where the “Bulleit” well, operated by Talos Energy was drilled to Total Depth. The well operator will complete the well as a production well in the first half of 2020 and then tie it back to the Talos-owned and operated Green Canyon 18 (GC 18A) facility approximately 16 kilometres west of the “Bulleit” well. The development will involve the use of a subsea completion that is common for projects of this nature and water depth in the Gulf of Mexico. “This is Otto’s fourth commercial discovery in the Gulf of Mexico and will be a highly important well in delivering the planned 5,000 barrels of oil per day production target by the end of 2020,” Otto Energy managing director Matthew Allen said. “Combined with Otto’s existing production assets already on stream, the completion of the GC21 field in the first half of 2020 will see Otto deliver on this important milestone target. “The GC 21 “Bulleit” has been a very challenging well to drill and has been capably managed by the Talos Energy operational and drilling team. “Otto would like to congratulate the Talos team on the outcome of the GC 21 “Bulleit” well and Otto looks forward to building on this successful result”.
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Tamarind Resources Pty Ltd Tamarind Resources is an energy company developing projects across Southeast Asia and Australasia. Its New Zealand operations include three 100 per cent owner/ operator oil reservoirs - Tui, Amokura, and Pateke in the Tui Area oil field. Oil is produced from the Tui, Amokura and Pateke oil reservoirs via subsea wells connected to a Floating Production Storage and Offloading (FPSO) vessel, the Umuroa that has a storage capacity of 700,000 barrels of stabilised crude oil. In Australia Tamarind has a strategic partnership with Triangle Energy. Tamarind provides technical, commercial and financial support to Triangle as it works towards being the leading Perth Basin focused E&P company at its Cliff Head project that is akin to Tui. Tamarind recently supported the acquisition of the remainder of the Cliff Head field by Triangle and its partner, Royal Energy by exercising various outstanding options providing US$1.2 million to Triangle. The Galoc Oil Field is situated in the Palawan basin of the Philippines, located 60 kilometres offshore in water depth of 290 to 400m. Tamarind owns 55.88 per cent equity and operatorship of the field. Four producing wells flow into FPSO Rubicon Intrepid, which has 450,000 barrels of storage capacity. Tamarind is working to bring to life the field life extension and production optimization projects since its August 2018 acquisition of Galoc. In Papua New Guinea, Tamarind has a commercial and technical alliance with South Pacific Resources, under which it supports SPR to develop its permits in PNG. Tamarind’s PNG experience covers the last decade or longer and SPR is using this experience to get the most out of its existing permits and to grow its position in this exciting oil and gas province.
Emperor Energy Limited
XCD Energy Limited
Emperor Energy’s major asset is the company’s 100 per cent-owned Vic/P47 exploration permit in the Gippsland Basin next to the BHP/ ExxonMobil Kipper field in Victoria. Emperor Energy recently announced an Independent Resource Statement for the Judith Gas Field within the VIC/P47 Exploration Permit, compiled by consultants 3D-GEO Pty Ltd. 3D-GEO assessed the gas-in-place and recoverable gas volumes in the Judith-1 gas discovery and Greater Judith Structure following the merging and reprocessing of the Northern Fields and 3D seismic surveys in VIC/P47 conducted in 2016/17. The statement declared a 2C Contingent Gas Resource of 150 billion cubic feet (Bcf); and a P50 Unrisked Prospective Gas Resource of 1.226 trillion cubic feet (Tcf). Using data from the Judith1 Well along with Seismic interpretation of the Judith Structure, 3D-GEO produced Dynamic Modelling Results for the Judith Structure. These included: »» A Four well development model indicated an 80 million standard cubic feet per day (MMscf/d) production rate can be maintained for 32 years; »» Gas production modelled at 29Bcf per year with 934Bcf of Raw Gas produced across 32 Years; and »» Simulated flow rates are of enough capacity to supply a plant of equivalent capacity to the existing onshore gas processing plant at Orbost. Emperor Energy has appointed Ocean Reach Advisory to find a suitable Exploration and Production Partner to participate in the exploration and development of the Judith Gas Field. The company is seeking a partner of suitable financial and technical capability to assist in the drilling of an exploration well at the offshore Judith Gas Field by February 2021. Based on successful exploration results the partner would then proceed with development of the field in conjunction with Emperor Energy.
XCD Energy was, until recently, known Entek Energy Limited. The company believes the change of name will enable it to write a new chapter in its history as an active oil explorer. Before changing its name the company had acquired Emerald House LLC, resulting in the transfer of the latter’s 100 per cent working interest in 13 National Petroleum Reserve of Alaska (NPR-A) leases covering 149,590 acres over the highly prospective Nanushuk trend on the North Slope of Alaska. Collectively known as Project Peregrine, the leases include the Willow discoveries to the north of the project that are currently being appraised and developed by ConocoPhillips. XCD has reprocessed approximately 600 kilometres of 1970s and 1980s 2D seismic data originally acquired by the United States Geological Survey that cover both its Leases and the Conoco operated Willow field. These now display an improvement in data quality that, along with other regional seismic and well data, is now being integrated into a more detailed study, named the Integrated Nanushuk Technical Regional Overview or INTRO Project using experts in the fields of sequence stratigraphy, basin modelling, geochemistry, petrophysics and core scanning technology that is expected to provide the company with a much improved understanding of the still emerging Nanushuk play. XCD anticipates the INTRO Project to be completed by late September 2019, at which time it is expected to lead to the company’s maiden Independent Prospective Resource Report for the area. Having received the new reprocessed dataset, XCD is now remapping the area and is in the process of finalising its own internal estimate of the prospective resource associated with one of the largest leads in the current exploration portfolio.
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ADX Energy Limited
Empire Energy Limited
ADX Energy’s stated strategy is to achieve exponential growth based on early entry to high impact exploration opportunities in proven oil and gas basins where there is good access to infrastructure, strong demand for energy, stable governments, attractive fiscal terms and above all, where management has had past experience and established firm relationships. ADX operates four oil and gas permits in North Africa and Europe, together with gold and base metal interests in Australia held via its stake in ASX-listed Riedel Resources. The company is headquartered in Perth and maintains strong ties to its portfolio with offices operating out of Baden (Austria), Tunis (Tunisia) and Bucharest (Romania). ADX’s Parta Block project is in one of Romania’s prolific hydrocarbon provinces. Geotechnical studies conducted by ADX revealed two independent play fairways with good upside potential. Several oil and gas fields have been discovered in the Parta Block since the late sixties with a total of 2P reserves of 12 million barrels of oil (MMbbl) of oil and 50 billion cubic feet (bcf) of gas. The block is considered underexplored based on seismically identified potential. Within the Parta Block, ADX recently spudded the Iecea Mica 1 appraisal well located in the Iecea Mare production license. The Sicily Channel project includes the previously discovered Dougga and the recently discovered Lambouka fields that comprise a combined resource that may exceed 500bcf of gas and in excess of 60MMbbls of liquids. ADX view both Dougga and Lambouka as appraisal and development opportunities. A Geostreamer (dual sensor) 3D seismic acquired in 2010 covers both discoveries and has identified additional medium to low risk exploration prospects while additional prospects have been identified on 2D seismic.
Empire Energy, via its 100 per cent-owned subsidiary company Imperial Oil & Gas Pty Ltd, holds a 100 per cent interest in 59,000 square kilometres of prospective shale gas exploration acreage in the Proterozoic McArthur Basin in the Northern Territory. Empire Energy was recently advised by the Northern Territory Department of Environment and Natural Resources of its acceptance of the company’s EP187 2D seismic program Environment Management Plan for final assessment. Empire has been working proactively with the Northern Territory Government to finalise the approval and has been in discussions with seismic contractors to carry out the seismic acquisition late in Q3 2019 - subject to final Government approvals and seismic crew availability. The primary goal of Empire’s EP187 2D seismic program is to gain a better understanding of the depth, thickness, lateral extent and geological complexity of the petroleum systems in EP187, especially the Velkerri Shale, in order to better inform future drilling programs and attract further capital support including from industry Joint Venture partners. The seismic program is fully funded from existing cash reserves. The Northern Territory government department also approved the Environment Management Plan for Santos’ 2019 EP161 McArthur Basin Drilling Program paving the way for a recommencement of appraisal drilling in 2019. The Santos EMP drilling and fracture stimulation involves two horizontal wells targeting the Velkerri Shale formation that technical analysis by Empire and its advisors has shown Velkerri Shale extends from EP161 into Empire’s EP187 tenement at depths and thicknesses ideal for petroleum development. Appraisal success by Empire’s neighbours is likely to attract further capital from oil and gas companies seeking to invest in the Northern Territory onshore shale sector.
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Comet Ridge Limited (ASX: COI) Brisbane-based Comet Ridge has several Coal Seam Gas (CSG) projects in key regions of Queensland and northern New South Wales. The company has certified gas resources at three projects and certified gas reserves at the Mahalo project in Queensland. The Comet Ridge strategy is to conduct CSG exploration and appraisal, with the aim of maturing exploration acreage from Gas Resources into Proven and Probable Gas Reserves. This process initially involves drilling wells in order to certify Prospective and Contingent Resources and then through further appraisal via pilot projects, with the intention of progressing into certified Reserves. The company likes to take high equity positions in its large exploration permits, such as its 100 per cent interest in two blocks in the Galilee Basin where it is currently drilling at the Albany 2 Well as part of the Galilee Deeps Joint Venture (GDJV) 2019 drilling program with Vintage Energy (ASX: VEN) that is earning a 30 per cent interest by way of funding 50 per cent of the first $10 million of the drilling costs. Comet Ridge achieved gas flow from the Albany 1 well in 2018, which was the first measured gas flow from the Lake Galilee Sandstone reservoir in the Galilee Basin. The GDJV considers the results from Albany 1 as very encouraging and is intent on completing drilling the full reservoir section at Albany 1, after the Albany 2 Well has been drilled. Albany 2 will be conventionally drilled to the top of the Lake Galilee Sandstone and then cored through the reservoir interval. Comet Ridge has 40 per cent equity in the Mahalo Block in the Bowen Basin, and CSG equity across PELs in the Gunnedah Basin in NSW.
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A.B.N. 47 106 A.B.N. 092 57747 106 092 577
Jade Energy Pte Ltd Jade Energy Holdings boasts a portfolio of projects inclusive of oil production and oil and gas exploration acreage in Western Australia and electricity retailing and trading in Singapore where the company now has over 85,000 customers through energy retail arm iSwitch. Jade, through its subsidiary company, RCMA Australia Pty Ltd, will shortly hold a 100 per cent interest the WA L14 oil and gas exploration and production license, located in the prospective oil and gas corridor of the North Perth Basin approximately 330 kilometres north of Perth. RCMA is operator of L14 which covers 9,835 acres and includes the Jingemia oilfield which produces light sweet high-quality crude oil from the prolific Dongara sandstone. Jingemia can process up to 22,000bbls per day of liquids and export up to 6000bopd. The central processing facility is supported by water flood, ample oil and water tankage, over 1.6 MW of power generation, crude oil fuel filtration, oil and water processing, and water bores. Oil production commenced at Jingemia in 2003 with initial rates above 4,000bopd and 4.6 million barrels have been produced to date. The Jingemia field has four producing oil wells which are currently being upgrade with ESPs, four water injection wells and an enhanced water flood system with pumps, supporting water bores and four injector wells. Oil production by year end is forecast at 455bopd. The first of eight exploration targets in L14 are in the process of being committed for drilling in 2020 to a depth of 2600m targeting the Dongara, Cattamurra, Kingia and High Cliff formations. Four northern prospects in the block have been estimated to have over 20 million bbls of oil in place.
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for the year ended 30 June 2018
for the year ended 30 June 2018
Oil & Gas Tipped to Perform Well in 2020 WALLY GRAHAM Resource and energy commodity markets have taken a belting lately, thanks in no small part to the US-China trade tensions and a flagrant disregard to supply changes. As the R-word (recession) is being bandied about by market and economy analysts the world’s industrial production cycle has continued its recent deceleration, which shows no intention of waning. Just how much further the decline can reach is most likely to depend on if, and by how much, the Chinese economy can grow and whether or not Donald Trump learns to play nicely with the United States’ trade partners. Gas Australian liquefied natural gas (LNG) exports are anticipated to perform well, despite their role on the global stage being enacted before a backdrop of overcapacity and low spot prices. Australia’s LNG export earnings in 2018-19 hovered around the $50 billion mark. Export volumes are forecast to increase these earnings to around $54 billion in 2019–20, before falling back to $50 billion as prices ease. Australia’s LNG export volumes are forecast to increase from an estimated 75 million tonnes in 2018–19 to 81 million tonnes in 2020–21, as new projects come on stream to extend the country’s LNG output. These include the expected ramp up in export volumes from the Prelude and Ichthys projects. Shell shipped the first LNG cargo from its Prelude project on 11 June, and is expected to increase production during 2019–20, while Train 2 at Ichthys is expected to come online during 2019. In its June Resources and Energy Quarterly, the Office of the Chief Economist predicted our LNG export prices to remain stable in 2019–20 and then decline in 2020–21. The Chief put this stability down to an appreciating exchange rate and easing LNG contract prices, at which most Australian LNG is sold. LNG spot prices, the Chief outlined, are forecast to remain low, as additions to global capacity outstrip increases in world demand. “Australia’s LNG exports are surging,” the chief economist said. Australia is in competition with Qatar for the title of the world’s largest LNG exporter over the first five months of 2019 with the former opening some daylight in April as Qatar’s exports dipped due to maintenance, however Qatar regained the edge on Australia in May. “Australia could be the world’s largest LNG exporter for the next few years,” the chief economist proposed. “Australia is forecast to edge past Qatar as the world’s largest LNG exporter (on an annual basis) when exports reach 78 million tonnes in 2019, and extend its lead in 2020 as exports climb to 81 million tonnes. “However, the narrow difference between the projected exports of the two nations means that Australia overtaking Qatar is not a certainty.”
That uncertainty arises due to a lack of clarity around the precise level of Qatar’s LNG exports. According to International Energy Agency (IEA) data Qatar’s has exported 75-76 million tonnes per annum over the past two years, while data from the International Group of Liquefied Natural Gas Importers (GIIGNL) has exports at 77-78 million tonnes during this time, and shipping data suggests Qatar exported 79-80 million tonnes of LNG over the same period. However Australia shapes up, it is expected to be surpassed as the world’s largest LNG exporter during the mid-2020s, not only by Qatar, but also the United States, as new projects in both countries come online. Our chief economist has revised Australia’s anticipated export earnings to the positiuve part of the graph compared to its March 2019 assessment. “Export earnings are now expected to be $1.1 billion higher in 2019–20, reflecting an upwards revision to the oil price forecast…and a downward revision to the AUD/USD exchange rate assumption,” the chief economist said. “An upward revision to prices has offset the impact of a downward revision to export volumes. “ConocoPhillips confirmed in June that it expected the Darwin LNG plant to shut down for 1-2 years, starting between 2021 and 2023, when gas from the Bayu-Undan field is exhausted. “While falling output at Darwin LNG was factored into the outlook for the March Resources and Energy Quarterly, production is now expected to decline at a faster rate.” Oil Oil markets have not been immune to the concerns shared by other global markets as fearless leaders around the world participate in domestic and international arm wrestling and sabre-rattling contests. All of which have extrapolated a period of volatility, creating demand and supply uncertainty in the short term. The oil market enjoyed a moment of steady price increases over the first five months of the year until hitting high volatility in June 2019, reflecting the uncertainty over global economic conditions and oil supply prospects. Even so, the chief has indicated that Australia’s oil export volumes are forecast to peak during the outlook period, as a side effect of new LNG projects coming online. Earnings from oil exports are forecast to continue in a positive direction, rising from $9.3 billion in 2018–19 to $12 billion in 2019–20 before falling back slightly to $11.2 billion in 2020–21. The anticipated 2019–20 peak reflects expected volume growth, a higher expected oil price and the impact of a weak Australian dollar. The price of oil increase steadily through the year until the middle of May, with the Brent crude benchmark rising from US$53 a barrel on 1 January to peak at US$74 on 16 May 2019. “Price growth was supported by the curtailment of supply under a production agreement, called the ‘Vienna Agreement’, between
OPEC, Russia, Kazakhstan, Mexico and seven other countries (collectively referred to as ‘OPEC+’),” the chief economist explained. “Should OPEC+ members decide not to continue the Vienna Agreement in early July, oil prices could be lower than forecast.” The problem with the agreement was that participants paid too close attention to the rules and by May, over-compliance combined with unplanned outages in Venezuela and Iran to decrease total world oil production by more than twice as much as was expected, despite continued growth in US output. From late May, oil prices plunged by 18 per cent with global sentiment reacting to fears about the state of the global economy, heightened risks exacerbated by the Trump v Jinping trade tensions and the other fires Trump was lighting in regards to Mexico and Iran. The recent hijackings and attacks on tankers in the Gulf of Oman have caused more than a few headaches. One that doesn’t get a great deal of press is the subsequent increased cost of shipping insurance. As we have seen in the past any further heightening of tensions in the Middle East could drive oil prices higher.
Non-OECD countries in the emerging market that takes in Asia and Australia are expected to account for all of the growth in global oil consumption in the near future. Non-OECD consumption forecast to reach 55 million barrels a day in 2021, up from 51 million in 2018. Breaking tis down we see consumption in China is expected to reach 14 million barrels a day in 2021, increasing at an average annual rate of 2.8 per cent; In India, the 2021 forecast is 5.4 million barrels a day, with 4.2 per cent annual growth. By contrast, consumption by the OECD nations is expected to remain steady at 48 million barrels a day as energy efficiency improves. “While Australia is part of the OECD, its consumption of oil products over the past decade has more closely resembled the non-OECD trend,” the chief economist noted. “Australia consumed 1.1 million barrels of oil in 2018. “In the absence of policy change, Australia’s consumption of oil products is expected to grow at an annual rate of 1.6 per cent to 2021.”
A GLOSSARY OF OIL & GAS INDUSTRY TERMINOLOGY BCF Billion Cubic Feet of Gas
MMBOE One million barrels of oil equivalent.
BOE Barrel of oil equivalent. A unit of energy approximately equal to the energy released by burning one barrel of crude oil.
MMBTU One million British thermal units.
BBL One stock tank barrel. BOED Barrels of oil equivalent per day. FEED Front-end engineering and design – part of a project’s life cycle. MBBL One thousand barrels of crude oil, bitumen, condensate or natural gas liquids. MBD One thousand barrels per day. MBOE One thousand barrels of oil equivalent. MCF One thousand standard cubic feet of natural gas. MMBBL One million barrels of crude oil, bitumen, condensate or natural gas liquids.
MMCF One million standard cubic feet of natural gas. MTPA Millions of tonnes per annum. Proven and probable reserves (2P) Proven reserves plus reserves that are deemed probable (at least 50 per cent likely) to be commercially recoverable. Also known as 2P or P50 reserves. Proven reserves (1P) Quantities of petroleum that can be estimated with reasonable certainty (at least 90 per cent) to be commercially recoverable. Also known as 1P or P90 reserves. Proven, probable and possible reserves (3P) Proven and probable reserves plus reserves that are deemed possible (at least 10 per cent likely) to be commercially recoverable. Also known as 3P or P10 reserves. TCF One trillion cubic feet of natural gas.
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The Official Conference Companion for the 2019 RIU GoodOil Conference